This section is intended to introduce various aspects of related technology, which may be associated with exemplary embodiments of the present techniques. This discussion is believed to be helpful in providing information to facilitate a better understanding of particular aspects of the present techniques. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
The production of hydrocarbons, such as oil and gas, has been performed for many years. To produce these hydrocarbons, one or more wells are typically drilled into subterranean locations, which are generally referred to as subsurface formations or basins. The wells are formed to provide fluid flow paths from the subterranean locations to the surface. The drilling operations typically include the use of a drilling rig coupled to a drillstring and bottom hole assembly (BHA), which may include a drill bit or other rock cutting devices, drill collars, stabilizers, measurement while drilling (MWD) equipment, rotary steerable systems (RSS), hole opening and hole reaming tools, bi-center bits, roller reamers, shock subs, float subs, bit subs, heavy-weight drill pipe, mud motors, and other components known to those skilled in the art. Once drilling operations are complete, the produced fluids, such as hydrocarbons, are processed and/or transported to delivery locations. As is well understood, drilling operations for the preparation of production wells, injection wells, and other wells are very similar. The present methods and systems may be used in cooperation with providing wells for hydrocarbon production, for injection operations, or for other purposes.
During the drilling operations, various limiters may hinder the rate of penetration (ROP). For instance, vibrations during drilling operations have been identified as one factor that limits the ROP. These vibrations may include lateral, axial and torsional vibrations, which may be present in a coupled or an uncoupled form. Axial vibrations occur as a result of bit/rock interactions and longitudinal drillstring dynamics; this mode may propagate to surface or may be dampened out by contact with the wellbore. Torsional vibrations may involve fluctuations in the torque at the bit and subsequent propagation uphole as a disturbance in the rotary motion of the drillstring. BHA lateral vibrations involve beam bending dynamics in the stiff pipe near the bit and do not usually propagate directly to the surface. However, lateral vibrations may couple to the axial and torsional vibrations and be experienced at the surface. Some authors have identified lateral vibrations as the most destructive vibrational mode to drilling equipment. The identification of the different types and amplitudes of the vibrations may be provided from downhole sensors in MWD equipment to provide either surface readout of downhole vibrations or stored data that can be downloaded at the surface after the “bitrun” or drilling interval is complete.
As drilling operations are expensive, processes for optimizing drilling operations based on the removal or reduction of system inefficiencies, or founder limiters, such as vibrations, may be beneficial. The downhole failure of a BHA or BHA component may be expensive and significantly increase the costs of drilling a well. The costs of BHA failures may include replacement equipment and additional time for a round-trip of the drillstring in the event of a washout (e.g., loss of drillstem pressure) with no parting of the drillstring. Further compounding these costs, sections of the wellbore may be damaged, which may result in sidetracks around the damaged sections of the wellbore. While many factors affect the durability of a BHA, vibrations have been identified as a factor that impacts equipment durability.
Accordingly, design tools (e.g., software applications and modeling programs) may be utilized to examine the drill string and BHA configurations and proposed drilling operations before implementation in a drilling operation. For example, vibrational tendencies may be identified along with drilling conditions, configuration designs, materials, and other operational variables that may affect the vibrational tendencies of the drill string and/or BHA during drilling operations. For example, modeling programs may represent the static force interactions in a BHA as a function of stabilizer placement. Although there have been numerous attempts to model BHA dynamics, there is a need for model-based design tools to simulate BHA designs for evaluating vibration effects as described herein.
In the numerous references cited in this application, there are both time and frequency-domain models of drilling assemblies. Because of the interest in direct force calculations for bit design and the rapid increase in computational capability, recent activity has focused on the use of direct time domain simulations and the finite element methods, including both two-dimensional and three-dimensional approaches. However, these simulations still require considerable calculation time, and therefore the number of cases that can be practically considered is limited. The finite element method has also been used for frequency-domain models, in which the basic approach is to consider the eigenvalue problem and solve for the critical frequencies and mode shapes. Only a couple of references have used the forced-frequency response approach, and these authors chose different model formulations than those discussed herein, including a different selection of boundary conditions. One reference used a similar condition at the bit in a finite element model, but a different boundary condition was specified at the top of the bottom hole assembly. This reference did not proceed further to develop the design procedures and methods disclosed herein.
Further, as part of a modeling system developed by ExxonMobil, a vibration performance index was utilized to provide guidance on individual BHA designs. A steady-state forced-frequency response dynamic model was developed to analyze a single BHA in batch mode from a command line interface, using output text files for graphical post-processing using an external software tool, such as Microsoft Excel™. This method was difficult to use, and the limitations of the interface impeded its application. The model has been utilized in some commercial applications within the United States since 1992 to place stabilizers to reduce the predicted vibration levels, both in an overall sense and specifically within designed rotary speed ranges. This model provided an End-Point Curvature index for a single BHA configuration. The End-Point Curvature index was limited to looking at performance from the perspective of a single point at the top of the BHA model. Moreover, the operational limitations of this prior model limited its application to individual BHA configurations for the determination of stabilizer placement. It was not capable of considering multiple BHA configurations conveniently or of conveniently varying a plurality of parameters for optimizing one or more factors other than the stabilizer location.
Other related material may be found in the following: G. Heisig et al., “Lateral Drillstring Vibrations in Extended-Reach Wells”, SPE 59235, 2000; P. C. Kriesels et al., “Cost Savings through an Integrated Approach to Drillstring Vibration Control”, SPE/IADC 57555, 1999; D. Dashevskiy et al., “Application of Neural Networks for Predictive Control in Drilling Dynamics”, SPE 56442, 1999; A. S. Yigit et al., “Mode Localization May Explain Some of BHA Failures”, SPE 39267, 1997; M. W. Dykstra et al., “Drillstring Component Mass Imbalance: A Major Source of Downhole Vibrations”, SPE 29350, 1996; J. W. Nicholson, “An Integrated Approach to Drilling Dynamics Planning, Identification, and Control”, SPE/IADC 27537, 1994; P. D. Spanos and M. L. Payne, “Advances in Dynamic Bottomhole Assembly Modeling and Dynamic Response Determination”, SPE/IADC 23905, 1992; M. C. Apostal et al., “A Study to Determine the Effect of Damping on Finite-Element-Based, Forced Frequency-Response Models for Bottomhole Assembly Vibration Analysis”, SPE 20458, 1990; F. Clayer et al., “The Effect of Surface and Downhole Boundary Conditions on the Vibration of Drillstrings”, SPE 20447, 1990; D. Dareing, “Drill Collar Length is a Major Factor in Vibration Control”, SPE 11228, 1984; A. A. Besaisow, et al., “Development of a Surface Drillstring Vibration Measurement System”, SPE 14327, 1985; M. L. Payne, “Drilling Bottom-Hole Assembly Dynamics”, Ph.D. Thesis, Rice University, May 1992; A. Besaisow and M. Payne, “A Study of Excitation Mechanisms and Resonances Inducing Bottomhole-Assembly Vibrations”, SPE 15560, 1988; and U.S. Pat. No. 6,785,641.
The prior art does not provide tools to support a design process as disclosed herein (i.e. a direct characterization of the drilling vibration behavior for myriad combinations of rotary speed and weight on bit), and there are no references to design indices or figures of merit to facilitate comparison of the behaviors of different assembly designs. Accordingly, there is a need for such software tools and design metrics to design improved bottom hole assembly configurations and drilling operations to reduce drilling vibrations.